Systems and methods to improve shut-down purge flow in a gas turbine system

ABSTRACT

A system includes a controller including a memory storing instructions and a processor that executes the instructions. The instructions cause the controller to control a steam turbine system coupled to a power generation system to release steam during deceleration of a gas turbine. The instructions cause the controller to receive a first temperature of the gas turbine and a rotational speed of the gas turbine. The instructions cause the controller to calculate an exhaust flow rate of the power generation system based on at least the first input signal and the second input signal. The instructions cause the controller to control the power generation system to isolate a fuel source from the gas turbine at a portion of normal operating speed of the gas turbine sufficient to achieve a predetermined purging volume during coast down of air flow through the power generation system based on the exhaust flow rate.

BACKGROUND

The present disclosure relates generally to power generation systems. Inparticular, the present disclosure relates to systems and methods toimprove shut-down purge flow in a gas turbine system.

Gas turbine generators, which are often used in combined cycle powerplants, may be shut-down and started-up based on demand for electricityin an area that the combined cycle power plant operates. Such demand mayconstantly fluctuate based on uncontrollable external factors. Once thegas turbine generators are shut-down, the gas turbine generators mustundergo a series of purging steps prior to restarting the gas turbinegenerators. The series of purging steps may be time consuming, and whenthe demand for electricity rises rapidly, it may inhibit the gas turbinegenerator from supplying additional electricity upon receiving anindication of the heightened demand.

BRIEF DESCRIPTION

Certain embodiments commensurate in scope with the originally claimedsubject matter are summarized below. These embodiments are not intendedto limit the scope of the claimed subject matter, but rather theseembodiments are intended only to provide a brief summary of possibleforms of the claimed subject matter. Indeed, the claimed subject mattermay encompass a variety of forms that may be similar to or differentfrom the embodiments set forth below.

In a first embodiment, a system includes a controller of a gas turbineand heat recovery steam generator (HRSG) system. The controller includesa memory storing instructions to perform operations of the gas turbineand HRSG system and a processor that executes the instructions. Theinstructions, when executed by the processor, cause the controller tocontrol a steam turbine system coupled to the gas turbine and HRSGsystem to release steam to relieve back pressure of a condenser of thesteam turbine system during deceleration of a gas turbine of the gasturbine and HRSG system. Additionally, the instructions cause thecontroller to receive a first input signal representative of a firsttemperature at an inlet of a compressor section of the gas turbine and asecond input signal representative of a rotational speed of the gasturbine. Further, the instructions cause the controller to calculate anexhaust flow rate of the gas turbine and HRSG system based on at leastthe first input signal and the second input signal. Furthermore, theinstructions cause the controller to control the gas turbine and HRSGsystem to isolate a fuel source from the gas turbine at a portion ofnormal operating speed of the gas turbine sufficient to achieve apredetermined purging volume during coast down of air flow through thegas turbine and HRSG system based on the exhaust flow rate.

In a second embodiment, a method includes utilizing a controller tocontrol a steam turbine system coupled to a gas turbine and heatrecovery steam generator (HRSG) system to release steam to relieve backpressure of a condenser of the steam turbine system. Additionally, themethod includes utilizing the controller to receive a first measurementof a first temperature of the gas turbine and HRSG system from a firstsensor. The measurement of the first temperature includes at least atemperature at an inlet of a gas turbine of the gas turbine and HRSGsystem. Further, the method includes utilizing the controller to receivea second measurement of a rotational speed of the gas turbine from asecond sensor. Furthermore, the method includes utilizing the controllerto calculate an exhaust volume flow rate of the gas turbine and HRSGsystem based on at least the first temperature and the rotational speedof the gas turbine. Moreover, the method includes utilizing thecontroller to obtain a purging volume of the gas turbine and HRSG systemthat is based on at least a volume of an HRSG of the gas turbine andHRSG system. The method also includes utilizing the controller tocontrol the gas turbine and HRSG system to isolate a fuel source fromthe gas turbine at a portion of normal operating speed of the gasturbine sufficient to achieve the purging volume during coast down ofair flow through the gas turbine and HRSG system based on the exhaustvolume flow rate.

In a third embodiment, a tangible, non-transitory,machine-readable-medium, includes machine-readable instructions toreceive a first measurement of a first temperature of a power generationsystem via a first sensor. The first temperature includes a temperatureat an inlet of a gas turbine of the power generation system.Additionally, the machine-readable-medium includes machine-readableinstructions to receive a second measurement of a rotational speed ofthe gas turbine via a second sensor. Further, themachine-readable-medium includes machine-readable instructions tocalculate exhaust flow rate of the power generation system based on atleast the first temperature and the rotational speed of the gas turbine.Furthermore, the machine-readable-medium includes machine-readableinstructions to control a steam turbine system coupled in a single shaftarrangement to the gas turbine to release steam to relieve back pressureof a condenser of the steam turbine system. Moreover, themachine-readable-medium includes machine-readable instructions tocontrol the power generation system to isolate a fuel source from thegas turbine at a portion of normal operating speed of the powergeneration system sufficient to achieve a purging volume during coastdown of air flow through the power generation system based at least onthe exhaust flow rate.

BRIEF DESCRIPTION OF THE DRAWINGS

These and other features, aspects, and advantages of the presentlydisclosed subject matter will become better understood when thefollowing detailed description is read with reference to theaccompanying drawings in which like characters represent like partsthroughout the drawings, wherein:

FIG. 1 is a block diagram of a gas turbine and heat recovery steamgenerator used to generate power in a combined cycle power plant, inaccordance with embodiments described herein;

FIG. 2 is a flowchart of a method for purging a gas turbine and heatrecovery steam generator during shut-down of the gas turbine and heatrecovery steam generator, in accordance with embodiments describedherein;

FIG. 3 is a flowchart of another method for purging a gas turbine andheat recovery steam generator during shut-down of the gas turbine andheat recovery steam generator, in accordance with embodiments describedherein;

FIG. 4 is a flowchart of a method for determining an isolation speed ofthe gas turbine during shut-down of the gas turbine and heat recoverysteam generator, in accordance with an embodiment of the presentdisclosure;

FIG. 5 is a block diagram of a gas turbine and heat recovery steamgenerator with inlet bleed heating valves used to generate power in acombined cycle power plant, in accordance with embodiments describedherein;

FIG. 6 is a flowchart of a method for purging a gas turbine and heatrecovery steam generator during shut-down by controlling inlet bleedheating valves, in accordance with embodiments described herein;

FIG. 7 is a block diagram of a gas turbine, a heat-recovery steamgenerator, and a steam turbine used to generate power in a combinedcycle power plant, in accordance with embodiments described herein;

FIG. 8 is a flowchart of a method for purging a gas turbine and heatrecovery steam generator during shut-down by controlling a steam valveof a steam turbine, in accordance with embodiments described herein;

FIG. 9 is a block diagram of a gas turbine and heat-recovery steamgenerator with fluid flow contributing components used to generate powerin a combined cycle power plant, in accordance with embodimentsdescribed herein; and

FIG. 10 is a flowchart of a method for purging a gas turbine and heatrecovery steam generator during shut-down by controlling fluid flowcontributing components to increase fluid flow through the gas turbineand heat recovery steam generator, in accordance with embodimentsdescribed herein.

DETAILED DESCRIPTION

One or more specific embodiments of the presently disclosed systems andtechniques will be described below. In an effort to provide a concisedescription of these embodiments, all features of an actualimplementation may not be described in the specification. It should beappreciated that in the development of any such actual implementation,as in any engineering or design project, numerousimplementation-specific decisions must be made to achieve thedevelopers' specific goals, such as compliance with system-related andbusiness-related constraints, which may vary from one implementation toanother. Moreover, it should be appreciated that such a developmenteffort might be complex and time consuming, but would nevertheless be aroutine undertaking of design, fabrication, and manufacture for those ofordinary skill having the benefit of this disclosure.

When introducing elements of various embodiments of the presentdisclosure, the articles “a,” “an,” “the,” and “said” are intended tomean that there are one or more of the elements. The terms “comprising,”“including,” and “having” are intended to be inclusive and mean thatthere may be additional elements other than the listed elements.

The present disclosure is generally directed to systems and methods formanaging purge flow of a gas turbine generator. For example, a systemmay include a gas turbine generator that may undergo a purging processprior to restarting after a shut-down period. To help decrease time usedto bring the gas turbine generator back online, the present disclosuredescribes systems and methods for providing a purging flow to the gasturbine generator during shut-down operations. As such, the purging flowprovided during the shut-down operations may limit or remove an amountof purging flow used prior to reaching a “purge complete” conditionduring a start-up operation of the gas turbine generator.

FIG. 1 is a block diagram of a system 10 (e.g., a power generationsystem) including a gas turbine 12 and a heat recovery steam generator(HRSG) 14, which is generally used to generate power in a combined cyclepower plant. The system 10 includes the gas turbine 12, the heatrecovery steam generator (HRSG) 14, and a fuel system 16. The fuelsystem 16 generally provides fuel to the gas turbine 12 for combustion.In particular, the fuel system 16 may include a piping configurationthat includes one or more pressure cavities that in conjunction with aplurality of valves supply fuel to the gas turbine 12 in a controlledmanner. As illustrated in FIG. 1, four fuel lines 18 a, 18 b, 18 c, and18 d provide fuel from the fuel system 16 to the gas turbine 12. It maybe appreciated that while four fuel lines 18 a-18 d are depicted, moreor less fuel lines 18 may also provide fuel to the gas turbine 12.

The exemplary gas turbine 12 may include a compressor section 20, acombustion section 22 and a turbine section 24. The compressor section20 may include a series of compressor stages, and each compressor stagemay include a plurality of compressor blades that rotate to compressair. The compressor section 20 generally receives ambient air at aninlet to the compressor section 20, compresses the air at the compressorstages, and provides the compressed air at the outlet of the compressorsection 20 to the combustion section 24. An inlet guide vane 26 at theinlet of the compressor section 20 can be adjusted (e.g., opened andclosed) to regulate a flow of air through the compressor section 20.

In the combustion section 22, fuel from the fuel system 16 is mixed withthe compressed air from the compressor section 20. The air/fuel mixtureis then ignited using an ignition device such as a spark plug to createa working gas. The working gas is directed through the turbine section24. The turbine section 24 may include a serial arrangement of stages,each stage having rotating blades known as buckets. The rotating bucketsare supported by a common rotary shaft. The working gas exiting thecombustion section 22 expands through the serial stages to causerotation of the buckets and therefore of the rotary shaft. In oneaspect, the rotary shaft of the turbine section 24 may be connected tothe compression blades in the compressor section 20 so that rotation ofthe rotary shaft drives air compression in the compressor section 20.The rotary shaft also extends beyond the turbine section 24 to anelectric generator (not shown) where the rotary motion of the rotaryshaft is converted into electrical power. Meanwhile the exhaustedworking gas from the turbine section 24 is directed toward the HRSG 14.

The HRSG 14 receives exhaust from the gas turbine 12 and uses theexhaust as a heat source to drive one or more steam turbines. The HRSG14 may include an inlet 28, a high pressure superheater (not shown) andone or more HRSG pressure sections 30 a, 30 b, and 30 c, which areoperable to generate steam at high pressure, intermediate pressure,and/or low pressure, respectively. Exhaust gas from the HRSG 14 is sentthrough an HRSG outlet duct 32 to an exhaust stack 34.

The gas turbine 12 and the fuel system 16 may be coupled to a controlunit 36 (e.g., a controller). The control unit 36 may be a computersystem that may include a memory 38, a set of programs 40 storinginstructions therein for shutting down the generator according to themethods described herein, and a processor(s) 42 (e.g., amicroprocessor(s)) that may execute the set of programs 40 to controlthe operation of the system 10 using sensor inputs and instructions fromhuman operators. Moreover, the processor 42 may include multiplemicroprocessors, one or more “general-purpose” microprocessors, one ormore special-purpose microprocessors, and/or one or more applicationspecific integrated circuits (ASICS), or some combination thereof.

For example, the processor 42 may include one or more reducedinstruction set (RISC) processors. The control unit 36 may be coupled tothe memory 38 that may store information such as control software, lookup tables, configuration data, etc. In some embodiments, the processor42 and/or the memory 38 may be external to the control unit 36. Thememory 38 may include a tangible, non-transitory,machine-readable-medium, such as a volatile memory (e.g., a randomaccess memory (RAM)) and/or a nonvolatile memory (e.g., a read-onlymemory (ROM)). The memory 38 may store a variety of information and maybe used for various purposes. For example, the memory 38 may store themachine-readable and/or processor-executable instructions 40 (e.g.,firmware or software) for the processor to execute, such as instructionsfor controlling the system 10. The storage device(s) (e.g., nonvolatilestorage) may include read-only memory (ROM), flash memory, a hard drive,or any other suitable optical, magnetic, or solid-state storage medium,or a combination thereof. The storage device(s) may store data (e.g.,position data, identification data, etc.), instructions (e.g., softwareor firmware), and any other suitable data. In some embodiments, thecontrol unit 36 may generate commands to adjust valves of the combustionsection 22 that regulate the fuel flow, adjust inlet guide vanes 26,maintain emissions (e.g., NO_(x) and CO emissions) in the exhaust of theturbine section 24, schedule the gas turbine 12 (e.g., setting desiredexhaust temperatures or combustor fuel splits), and activate othercontrol settings on the gas turbine 12. The control unit 36 may controlvalve configurations at the fuel system 16 as well as monitor variousparameters, such as pressure at the fuel system 16, gas levels in thegas turbine 12, etc.

Additionally, a set of sensors 44 may be disposed along a flow path ofthe system 10. The sensors 44 may monitor operation of the system 10 bymeasuring, for example, a temperature of the air and/or the componentsof the system 10 at the locations of the sensors 44. In someembodiments, one or more of the sensors 44 that may detect variousobservable conditions of one or more components of the gas turbine 12(e.g., the generator 26, the intake 20, etc.) and/or the ambientenvironment. In some embodiments, a plurality of redundant sensors maybe used to measure the same measured condition. For example, a pluralityof redundant temperature sensors 44 may monitor ambient temperaturesurrounding the system 10, compressor discharge temperature, turbineexhaust gas temperature, and other temperature measurements of the gasstream through the system 10. For example, the temperature sensors 44may be located at an inlet of the compressor section 20, along anexhaust region of the gas turbine 12, and/or at the exhaust stack 34 ofthe HRSG 14. Similarly, a plurality of redundant pressure sensors 44 maymonitor ambient pressure, and static and dynamic pressure levels at thecompressor section 20, exhaust stack 34, and/or at other locations inthe gas stream through the system 10. A plurality of redundant sensors(not shown) may also include flow sensors, speed sensors, flame detectorsensors, valve position sensors, guide vane angle sensors, humiditysensors, or the like, that sense various parameters pertinent to theoperation of the system 10. The temperature sensors 44, the pressuresensors 44, and any other redundant sensors may all communicativelycouple to the control unit 36.

As used herein, a “parameter” refer to a measurable and/or estimablequality that can be used to define an operating condition of the gasturbine 10, such as temperature, pressure, gas flow, or the like, atdefined locations in the system 10. Some parameters are measured, i.e.,are sensed and are directly known. Other parameters are estimated by amodel and are indirectly known. The measured and estimated parametersmay be used to represent a given turbine operating state.

The present disclosure provides methods of shutting down the system 10in such a manner to be in a ready state for a restart (e.g., a “purgecomplete” condition) within a reduced amount of time from shutdown. A“purge complete” condition is a general indication that combustiblegases are substantially diluted and/or removed from the system 10 andthat the system 10 is in a desired state for startup of the gas turbine12. A “purge complete” condition can also involve removal of risksassociated with remaining fuel in the gas turbine 12, exhaust stack 34,and downstream equipment, placing the fuel system 16 in a specificstartup configuration, completing a leak test of the fuel system 16,securing the fuel system 16 to a standby condition, and monitoringconditions after establishing the desired conditions.

With the foregoing in mind, FIG. 2 is a method 74 for purging the system10 during shut-down of the system 10. It may be appreciated that theblocks of method 74 are not necessarily sequential steps and thatcertain blocks may be performed simultaneously or in a different order.As discussed above, receiving purging credit during shut-down of thesystem 10 may enable a quicker restart of the system 10 as the system 10may be in a “purge complete” condition upon completion of the shut-down.To accomplish purging during shut-down of the system 10, at block 75,the control unit 36 may determine a purge volume that achieves thepurging credit. The purge volume may be a static value for the system10, and the purge volume may be based on a volume of the HRSG 14. Forexample, in some embodiments, the purge volume to achieve the purgingcredit may be five volume exchanges of air flow that cycle through thesystem 10 while the gas turbine 12 operates above a minimum purgingspeed. A volume exchange may be defined as a volume of air flow cycledthrough the system 10 that is equivalent to a volume of the HRSG 14.

Subsequently, at block 76, the control unit 36 may receive a shut-downnotification. The shut-down indication may be a result of a decreasedpower demand in a power grid coupled to the system 10. Additionally, theshut-down indication may also be a result of a manual shut-downindication or any other stimulus where a shut-down of the system 10 isdesirable.

Accordingly, at block 77, the fuel may be isolated from the gas turbine12. In isolating the fuel from the gas turbine 12, the combustion flamemay be extinguished and the system 10 may provide coast down air flowthrough the system. The coast down air flow may refer to air flowingthrough the system 10 due to residual (i.e., unpowered) rotation of thebuckets of the turbine section 24 and/or compressor blades of thecompressor section 22 after extinguishing the combustion flame.

Additionally, it may be appreciated that isolating the fuel from the gasturbine 12 may occur at approximately 40 percent (or another percentage)of a normal operating speed of the gas turbine 12 to meet the desiredpurge flow volume. Normal operating speed of the gas turbine 12 may bedefined as an operating speed of the gas turbine 12 at which the gasturbine 12 is operated during standard power generating operation.However, it may also be appreciated that depending on the temperature ofthe exhaust and/or a magnitude of the volume that achieves the purgecredit, the fuel may be isolated at greater than approximately 40percent or less than approximately 40 percent of the normal operatingspeed of the gas turbine 12. In certain embodiments, the fuel may beisolated at approximately 30 to 100 percent, 30 to 65 percent, 65 to 100percent, and all subranges therein, of the normal operating speed of thegas turbine 12. For example, the fuel may be isolated at approximately30 percent, 35 percent, 45 percent, 50 percent, 55 percent, 60 percent,65 percent, 70 percent, 75 percent, 80 percent, 85 percent, 90 percent,95 percent, or 100 percent of the normal operating speed of the gasturbine 12 and still achieve the desired purge depending on the exhausttemperature at the shut-down request and the magnitude of the purgevolume.

Further, the control unit 36 may determine the operating speed of thegas turbine 12 at which the fuel is isolated (i.e., isolation speed).For example, if the exhaust temperature is relatively low during aspecific shut-down operation, more inlet air flow and time may be usedto achieve the desired purging volume. Accordingly, the control unit 36,upon determining the desired purging volume, may instruct the system 10to isolate the fuel from the gas turbine 12 at a higher than nominalisolation speed. Alternatively, if the exhaust temperature is relativelyhigh during a specific shut-down operation, less inlet air flow and timemay be used to achieve the desired purging volume. In such a situation,the control unit 36 may instruct the system 10 to isolate the fuel at alesser than nominal isolation speed. In other words, the greater theexhaust temperature during the specific shut-down operation, the lowerthe isolation speed needed when isolating the fuel. In this manner, thecontrol unit 36 is able to account for various speeds of the gas turbine12 during a shut-down operation to meet the desired purging volume ofthe purging operation. In certain embodiments, the control unit 36 mayutilize at least in part historical data (e.g., historical margins formeeting the purge credit parameters) to determine the isolation speed asdescribed in greater detail below.

At block 78, inlet temperatures, exhaust temperatures, and therotational speed of the gas turbine 12 are measured. Measuring the inlettemperatures and exhaust temperatures enables the control unit 36 toaccurately account for purge volumes based on increased temperature ofthe gas flowing through the system 10. For example, during shut-down ofthe system 10, a temperature difference between the exhaust temperatureand the inlet temperature indicates that the warmer exhaust temperaturewould result in the expansion of air initially provided at an inlet ofthe compressor section 20 of the gas turbine 12 or any other inletlocation of the gas turbine 12. Accordingly, with expansion of the airat the inlet temperature, less compressor inlet flow is used to completethe purge requirement. That is, less compressor inlet flow is used togenerate a flow to adequately meet the purge credit volume of air. Thevalues measured in block 78 are continuously monitored during theshut-down operation to maintain accurate measurements of the purgingflow passing through the system 10.

Subsequently, at block 79, a purge flow rate may be calculated based onthe exhaust and inlet temperature measurements and the measurements ofthe rotational speed of the gas turbine 12. As described above, arelationship in temperature between the exhaust and the inlet air flowmay provide an indication as to the amount that the inlet air flowexpands as the inlet air flow travels along a gas flow path of the gasturbine 12. Accordingly, the temperatures at the inlet and/or theexhaust of the gas turbine 12, in addition to the rotational speed ofthe gas turbine 12, may enable a calculation of an accurate purge flowrate of the system 10.

To achieve adequate purge to restart the system 10, a certain number ofvolume exchanges (e.g., 4, 5, etc.) of air flow may cycle through thesystem while buckets of the gas turbine 12 and/or blades of thecompressor section 20 provide a flow rate at a rate greater than acertain percent (e.g., eight percent or another percent) of the flowrate of the gas turbine 12 during standard operation. In someembodiments, the percent flow rate may be greater or less duringstandard operation based on the properties of the gas turbine 12. Thatis, a purging volume that achieves the adequate purge may be defined asa certain number of volume exchanges of air flow that cycle through thesystem. The number of volume exchanges may be determined by requirementsby the original equipment manager or industrial codes that reference acertain number of exchanges of a defined volume of equipment in a gaspath of the gas turbine or a rate. The volume of air flow may be adefined volume of the HRSG 14 through which air flows. Based on theexpansion of the inlet air flow, less inlet air flow may be used toachieve the certain number of volume exchanges of air flow through thesystem. Accordingly, the control unit 36 may calculate an amount ofinlet air flow that achieves the exhaust flow to meet the desired purgecredit value. Alternatively, the exhaust flow may be calculated by thecontrol unit 36 based on the temperature sensors 44 at the inlet, at theexhaust of the turbine section 24, and/or along a flow path through theHRSG 14. This calculation may provide an indication of a point in timeafter securing the fuel at which the desired purge is achieved based onthe air flow at the exhaust of the system 10. That is, the control unit36 may determine an amount of time used to achieve the desired purgingvolume based on the inlet and exhaust temperature of the system 10, thespeed of the buckets of the gas turbine 12 and/or the blades of thecompressor section 20, and the volume of the HRSG 20.

By way of example, in comparing mass flow of the exhaust air flow atambient temperatures (e.g., purging during system start-up) and massflow of the exhaust at 300-400 degrees Celsius (e.g., purging duringsystem shut-down), the volume may be increased by approximately 30-40percent with the heightened temperature values. That is, it may takeapproximately 30-40 percent less time for the system 10 to achieve thedesired purge at shut-down than it does for the system 10 to achieve thedesired purge during start-up. Accordingly, in establishing the purge atshut-down, the system 10 may be brought back online much faster thanwhen the system 10 establishes the purge at start-up.

With this in mind, at block 80, a cumulative purged volume may beintegrated. That is, the control unit 36 may track a volume of the purgeflow that has been accumulated from the system 10. For example, eachtime block 80 is executed, the control unit 36 may update the cumulativepurged volume based on current inlet temperatures, exhaust temperatures,and/or rotational speeds of the gas turbine 12. Accordingly, the controlunit 36 may keep track of when the purge volume is met.

At decision block 81, the control unit 36 may make the determination ofwhether the purge volume has been met by the system 10. If the purgevolume has been met, at block 82, the control unit 36 may indicate thatthe purge has been established. By indicating that the purge has beenestablished, the control unit 36 may not instruct the system 10 toperform another purge operation when the system 10 is restarted.

If the purge volume has not been met at decision block 81, then thecontrol unit, at decision block 83, may determine if the purge flow rateis greater than the minimum purge flow requirement. If the purge flowrate is greater than the minimum purge flow requirement, then the method74 returns to block 78, and the loop may continue until the purge volumeis met at decision block 81 or the purge flow rate is less than theminimum purge flow requirement at decision block 83. When the purge flowrate is less than the minimum purge flow requirement at decision block83, the control unit 36 may indicate that the purge has not beenestablished at block 84. Accordingly, when the system 10 is restarted,the system 10 may be instructed by the control unit 36 to undergo apartial purging operation to achieve the remaining purge volume toestablish the purge, or the control unit 36 may restart the system 10after undergoing a complete purging operation.

FIG. 3 is an alternative embodiment of a method 89 for purging thesystem 10 during shut-down of the system 10. Method 89 is similar tomethod 74 with the exception what happens if the purge volume has notbeen met at decision block 81. If the purge volume has not been met atdecision block 81 in method 89, then, at block 93, the control unit 36may utilize a starting system (e.g., static starting system such as aload commutated inverter (LCI), electric motor starting package, dieselengine starting package, etc.) to maintain the gas turbine engine 12 ator above a minimum purge flow speed (while the method 89 returns toblock 78 so the loop may continue) until the purge volume is met atdecision block 81.

As discussed above, in some embodiments, the control unit 36, at block78, may control when the fuel is isolated from the gas turbine 12 basedon historical margins for meeting the purge credit parameters.Accordingly, FIG. 4 is a method 85 for determining when the fuel isisolated from the gas turbine 12. At block 86, historical data may bestored in the memory 38 of the control unit 36. The historical data mayrelate to historical amounts of accumulated volume and/or margins to therequired volume taken by the gas turbine 12 under various conditions(e.g., inlet temperature, exhaust temperature, and isolation speed) toreach a minimum purge flow requirement of the gas turbine 12.

Using the historical data, at block 87, the control unit 36 maydetermine (e.g., actively learn) an isolation speed of the gas turbine12 at which the gas turbine 12 may achieve the purge prior to the gasturbine 12 reaching the minimum purge flow requirement. That is, thecontrol unit 36 may use the historical data stored in the memory 38, incombination with the current operating parameters of the gas turbine 12(e.g., inlet temperature, exhaust temperature, and rotational speed), todetermine an isolation speed of the gas turbine 12 at which the fuel isisolated from the gas turbine 12. Such a determination may enablegreater precision in ensuring that the purge is achieved because thespeed at which the fuel is isolated may be a speed that historicallykeeps the gas turbine 12 above the minimum purge flow requirement forlong enough to achieve the purge. In certain embodiments, the controlunit 36 may store the determined isolation speed (e.g., in memory 38).The stored isolation speed may be utilized in subsequent purgeoperations. In some embodiments, the stored isolation speed may bemodified and/or updated by the control unit 36. It should be noted thatbesides purge volume other factors may affect isolation speed. Inparticular, the isolation speed may vary between different gas turbines.

At decision block 88, the control unit 36 may compare the determinedisolation speed to a maximum speed (e.g., determined by the hardwarelimits). If the determined isolation speed is not greater than or equalto the maximum speed then, at block 95, the control unit 36 may instructthe fuel system 16 to isolate the fuel at the speed determined at block87. If the determined isolation speed is less than the maximum speed,then at block 97 the control unit 36 may utilize the starting system(e.g., static starting system such as a load commutated inverter (LCI),electric motor starting package, diesel engine starting package, etc.)to maintain the gas turbine engine 12 at or above a minimum purge flowspeed.

Because the control unit 36 takes into account temperature to determinethe desired purge volume, the air flow through the system is minimizedand thermal stresses on the equipment of the system 10 are reduced.Further, sensor based air flow calculations may provide a moreconsistent approach to purging the system 10. For example, instead ofpurging a certain number of volumes (e.g., five volumes) of ambient airtemperature input into the system 10 during each purging operation, thecontrol unit 36 determines the actual air flow through the system 10taking expanding gas volumes of heated ambient air into account.Accordingly, each purging operation purges an exhaust volume that moreaccurately matches a desired purge volume to achieve purge.

FIG. 5 is a block diagram of the system 10 (e.g., a power generationsystem) including the gas turbine 12 and the heat recovery steamgenerator (HRSG) 14, which is generally used to generate power in acombined cycle power plant. The system 10 includes the gas turbine 12,the heat recovery steam generator (HRSG) 14, and the fuel system 16.Generally, the system 10 of FIG. 5 may operate in a similar mannerduring a purging process of a shut-down operation to the system 10described in FIG. 1 with a modification to an inlet bleed heating system91 of the gas turbine 12.

For example, the inlet bleed heating system 91 of the gas turbine 12 mayrelieve pressure in the compressor section 20 and increase a temperatureof fluid provided to the inlet of the compressor section 20. Byrelieving the pressure and increasing the temperature, the inlet bleedheating system 91 may protect the compressor section 20 from stalling.The inlet bleed heating system 91 may bleed heated compressor dischargefrom the compressor section 20 by way of a fluid flow line 92. Generallythe fluid flow line 92 may couple to an inlet bleed heating valve 94that provides the heated compressor discharge to the inlet of thecompressor section 20 by way of a fluid flow line 96. The inlet bleedheating valve 94 may be controlled by the control unit 36 to increase ordecrease the heated compressor discharge from the compressor section 20to the inlet of the compressor section 20.

Additionally, extraction valve 98 may be coupled to the fluid flow line92 to provide heated compressor discharge to an exhaust plenum 99 of theturbine section 24 by way of a fluid flow line 100. During a purgingoperation, the additional inlet bleed heating valve 98 may be at leastpartially opened to provide at least a portion of the heated compressordischarge to the exhaust plenum 99 of the gas turbine 12. By applyingthe heated compressor discharge to the exhaust plenum 99, additionalpurging volume flow is provided in addition to the coast down purge flowto the HRSG 14 provided from the inlet of the compressor section 20. Forexample, the heated compressor discharge lowers the compressor operatingline, increase the compressor inlet flow, and therefore the total flowinto HRSG 14. The additional purging volume flow may be determined bythe control unit 36 via volume accumulation instructions or a model. Thedetermination of the additional purging volume flow may be based ondischarge extraction stroke, measured flow, and/or a change in thecompressor pressure ratio. This operation would have may be useful atlow speeds due to compressor speed line shapes. In addition toincreasing total flow, it would lower the speed at which the system 10reaches the minimum flow, further increasing the total accumulated flow.Because the system 10 may include a minimum flow requirement for thepurge operation, the addition of the heated compressor discharge fromthe inlet bleed heating system 14 to the exhaust plenum 99 may provide asufficient increase in the purge flow for the system 10 to achieve thedesired purge credit volume of air during a shut-down operation of thesystem 10.

Further, it may be appreciated that the valves 94 and 98 may generallybe closed during a shut-down operation of the system 10. Therefore,during shut-down operations, an operating line, which may be defined asa compressor pressure ratio at a purging flow rate, of the compressorsection 20 may generally be greater than when one or both of the valves94 and 98 are opened. The heightened operating line may result inincreased pressure within the compressor section 20, which may providesufficient resistance to drive down a speed of the compressor bladesduring a shut-down operation to a level below a speed that provides anadequate purging flow rate. Accordingly, by opening one or both of thevalves 94 and 98, the speed of the compressor blades during a shut-downoperation may not decrease as fast as when the valves 94 and 98 areclosed. Additionally, when the valve 98 is opened, the operating line ofthe compressor section 20 may be reduced (decreasing the compressorpressures), and the heated compressor discharge provided from thecompressor section 20 to the exhaust plenum 99 may provide an increaseto the purging flow rate (increasing the total flow, while creating lessresistance and a slower deceleration) to enable the desired purge creditvolume to be reached in a shorter amount of time. Moreover, becausedirecting the heated compressor discharge to the exhaust plenum 99reduces the operating line of the compressor section 20 and increasespurge flow volume provided to the exhaust plenum 99, the system 10 mayreduce an amount of time the starting system (e.g., static startingsystem such as a load commutated inverter (LCI), electric motor startingpackage, diesel engine starting package, etc.) to maintain the gasturbine engine 12 at or above a minimum purge flow speed. Additionally,in some embodiments, the system 10 may eliminate the use of the startingsystem during a purging operation altogether. With the system 10, thestarting system may provide power to the system 10 upon starting the gasturbine 12, or to maintain the gas turbine 12 above a minimum purgingflow rate when the gas turbine 12 is shut down.

Turning now to FIG. 6, a flowchart of a method 110 for purging thesystem 10 during shut-down using the inlet bleed heating system 91 isillustrated. It may be appreciated that the blocks of the method 110 arenot necessarily sequential steps and that certain blocks may beperformed simultaneously or in a different order. As discussed above,receiving purging credit during shut-down of the system 10 may enable aquicker restart of the system 10, as the system 10 may be in a “purgecomplete” condition upon completion of the shut-down. To accomplishpurging during shut-down of the system 10, at block 112, the controlunit 36 may receive a shut-down notification. The shut-down notificationmay be a result of a decreased power demand in a power grid coupled tothe system 10. Additionally, the shut-down notification may also be aresult of a manual shut-down notification or any other stimulus where ashut-down of the system 10 is desirable.

Subsequently, at block 114, the control unit 36 may instruct the inletbleed heat valves 94 and/or 98 to open or to remain open. By controllingthe valves 94 and/or 98 to open or to remain open, the heated compressordischarge may be transmitted to the inlet of the compressor section 20and/or the exhaust plenum 99 of the gas turbine 12. In particular, thecontrol unit 36, at block 116, may control the heated compressordischarge to the exhaust plenum 99 to lower the operating line of thegas turbine 12 and to increase the total purge flow as a result ofincreased pressure in the compressor section 20. Further, returning theheated compressor discharge to the exhaust plenum 99 may provideadditional purge volume to assist in meeting the desired purge volumecredit. It may be appreciated that in some embodiments, the valve 94 mayremain closed while the valve 98 is open during a purging operation.

At block 118, the fuel may be isolated from the gas turbine 12. Incertain embodiments, other components of the system may be isolated. Inisolating the fuel from the gas turbine 12, the combustion flame may beextinguished and the system 10 may provide coast down air flow throughthe system in addition to the heated compressor discharge provided bythe valve 98 of the inlet bleed heating system 91. The coast down airflow may refer to air flowing through the system 10 due to residual(i.e., unpowered) rotation of the buckets of the turbine section 24and/or compressor blades of the compressor section 22 afterextinguishing the combustion flame.

Additionally, it may be appreciated that isolating the fuel from the gasturbine 12 may occur at approximately 40 percent (or another percentage)of a normal operating speed of the gas turbine 12 to meet the desiredpurge flow volume. In certain embodiments, the fuel may be isolated atapproximately 30 to 100 percent, 30 to 65 percent, 65 to 100 percent,and all subranges therein, of the normal operating speed of the gasturbine 12. For example, the fuel may be isolated at approximately 30percent, 35 percent, 45 percent, 50 percent, 55 percent, 60 percent, 65percent, 70 percent, 75 percent, 80 percent, 85 percent, 90 percent, 95percent, or 100 percent of the normal operating speed of the gas turbineengine 12. Normal operating speed of the gas turbine 12 may be definedas an operating speed of the gas turbine 12 at which the gas turbine 12is operated during standard power generating operation. However, it mayalso be appreciated that depending on the temperature of the exhaust, amagnitude of the volume that achieves the purge, and/or the purge flowprovided by the heated compressor discharge, the fuel may be isolated atgreater than a nominal isolation speed or less than a nominal isolationspeed. In certain embodiments, the fuel may be isolated at approximately30 to 100 percent, 30 to 65 percent, 65 to 100 percent, and allsubranges therein, of the normal operating speed of the gas turbine 12.For example, the fuel may be isolated at approximately 30 percent, 35percent, 45 percent, 50 percent, 55 percent, 60 percent, 65 percent, 70percent, 75 percent, 80 percent, 85 percent, 90 percent, 95 percent, or100 percent of the normal operating speed of the gas turbine 12. Forexample, the fuel may be isolated at the certain percent of the normaloperating speed of the gas turbine 12 and still achieve the desiredpurge depending on the exhaust temperature at the shut-down request andthe magnitude of the purge volume.

Further, the control unit 36 may determine the operating speed of thegas turbine 12 at which the fuel is isolated. For example, if theexhaust temperature is relatively low during a specific shut-downoperation, more inlet air flow and time may be used to achieve thedesired purging volume. Accordingly, the control unit 36, upondetermining the desired purging volume, may instruct the system 10 toisolate the fuel from the gas turbine 12 at an isolation speed asdescribed above. Alternatively, if the exhaust temperature is relativelyhigh during a specific shut-down operation, less inlet air flow and timemay be used to achieve the desired purging volume. In such a situation,the control unit 36 may instruct the system 10 to isolate the fuel atapproximately 30 percent of the normal operating speed of the gasturbine 12. In this manner, the control unit 36 is able to account forvarious speeds of the gas turbine 12 during a shut-down operation tomeet the desired purging volume of the purging operation.

As the system 10 coasts down, at block 120, an increased purge volume isapplied to the system 10 until the determined purge credit volume isachieved. That is, the valve 98 may remain open until the determinedpurge credit volume is achieved by the system 10. Accordingly, a speedof the compressor blades may maintain a speed above the minimum purgeflow velocity for a sufficient amount of time to meet the purge creditvolume.

Subsequently, upon reaching the purge credit volume, at block 122, theinlet bleed heat valves 94 and/or 98 may be closed or may remain closed.By closing the valves 94 and 98, the operating line of the compressorsection 20 may increase, which may result in the speed of the compressorblades of the compressor section 20 to quickly decrease. Therefore, thesystem 10 may quickly shut-down after the desired purge credit volume ismet.

FIG. 7 is a block diagram of the system 10 (e.g., a power generationsystem) including the gas turbine 12 and the heat recovery steamgenerator (HRSG) 14, which is generally used to generate power in acombined cycle power plant. The system 10 includes the gas turbine 12,the heat recovery steam generator (HRSG) 14, the fuel system 16, and asteam turbine system 128. Generally, the system 10 of FIG. 7 may operatein a similar manner during a purging process of a shut-down operation tothe system 10 described in FIG. 1 with modifications to operation of thesteam turbine system 128 to increase the purging volume flow duringcoast down of the system 10. In addition, the system 10 may includesystems on the HRSG 14 or back up fuel systems that may be involved inthe isolation.

In particular, the steam turbine system 128 may receive steam from theHRSG 14 by way of a steam transport line 130. The steam may provide apropulsive force on a steam turbine 132 of the steam turbine system 128to generate power. From the steam turbine 132, the steam may travel, byway of an additional steam transport line 134, to a condenser 136. Inthe condenser 136, the steam may be cooled and condensed to water andtransported back to the HRSG 14 by way of a water transport line 138.

It may be appreciated that, in some embodiments, the steam turbine 132and the gas turbine 12 may both be a part of a single shaft generatorsystem. That is, both the steam turbine 132 and the gas turbine 12generate power from the same shaft of a generator system. Further,reducing back pressure of a condenser of the steam turbine 132 mayreduce steam turbine drag on the shaft. By reducing the back pressure ofthe condenser of the steam turbine 132 during a shut-down operation ofthe system 10, which includes the steam turbine 132, the deceleration ofthe purge flow during coast down of the system 10 may be slowed. Forexample, by limiting the drag provided by the steam turbine 132 on theshaft, the system 10 will take a longer amount of time to decelerate tothe minimum purge flow rate. Accordingly, the system 10 may achieve thedesired purge flow credit without having to hold the system 10 at theminimum purge flow rate with the starting system. Additionally, in someembodiments, the system 10 may achieve the desired purge flow credit byreducing the back pressure of the condenser of the steam turbine 132 toreduce an amount of time during which the starting system holds thesystem 10 at the minimum purge flow rate. The back pressure of thecondenser of the steam turbine 132 via managing (via the control unit36) components of the steam turbine 132 (e.g., steam valve 140, coolingand sealing air system 142, etc.).

Turning now to FIG. 8, a flowchart of a method 150 for purging thesystem 10 during shut-down using the steam turbine system 128 isillustrated. It may be appreciated that the blocks of the method 150 arenot necessarily sequential steps, but may be performed simultaneously orin any order. As discussed above, purging during shut-down of the system10 may enable a quicker restart of the system 10 as the system 10 may bein a purged condition upon completion of the shut-down. To accomplishpurging during shut-down of the system 10, at block 152, the controlunit 36 may receive a shut-down notification. The shut-down notificationmay be a result of a decreased power demand in a power grid coupled tothe system 10. Additionally, the shut-down notification may also be aresult of a manual shut-down notification or any other stimulus where ashut-down of the system 10 is desirable.

Subsequently, at block 154, the control unit 36 may instruct the steamvalve 140 of the steam turbine 132 to be in a shutdown purge position.Additionally or alternatively, the control unit 36 may instruct thecooling and sealing air system 142 to open to a maximum flow capacity.By controlling the steam valve 140 and/or the cooling and sealing airsystem 142 to open or to remain open, the back pressure of the condenserof the steam turbine 132 may be relieved. By relieving the back pressureof the condenser, drag on a shaft of the steam turbine 132 resultingfrom the back pressure of the condenser may be reduced. Additionally, ina single shaft system (e.g., with both the gas turbine 12 and the steamturbine 132 driving the same shaft coupled to the generator), reducingthe drag on the shaft may slow the deceleration of the purge flow of thesystem 10 during the shut-down operation.

At block 156, the fuel may be isolated from the gas turbine 12. Inisolating the fuel from the gas turbine 12, the combustion flame may beextinguished and the system 10 may provide coast down air flow throughthe system 10. The coast down air flow may refer to air flowing throughthe system 10 due to residual (i.e., unpowered) rotation of the bucketsof the turbine section 24, the compressor blades of the compressorsection 22, and/or the buckets and compressor blades of the steamturbine 132 after extinguishing the combustion flame.

Additionally, it may be appreciated that isolating the fuel from the gasturbine 12 may occur at approximately 40 percent (or another percentage)of a normal operating speed of the gas turbine 12 to meet the desiredpurge flow volume. Normal operating speed of the gas turbine 12 may bedefined as an operating speed of the gas turbine 12 at which the gasturbine 12 is operated during standard power generating operation.However, it may also be appreciated that depending on the temperature ofthe exhaust, a magnitude of the volume that achieves the purge, and/orthe deceleration of the purge flow of the system 10, the fuel may beisolated at greater than a nominal isolation speed or less than anominal isolation speed. In certain embodiments, the fuel may beisolated at approximately 30 to 100 percent, 30 to 65 percent, 65 to 100percent, and all subranges therein, of the normal operating speed of thegas turbine 12. For example, the fuel may be isolated at approximately30 percent, 35 percent, 45 percent, 50 percent, 55 percent, 60 percent,65 percent, 70 percent, 75 percent, 80 percent, 85 percent, 90 percent,95 percent, or 100 percent of the normal operating speed of the gasturbine 12 and still achieve the desired purge depending on the exhausttemperature at the shut-down request, the magnitude of the purge volume,and the deceleration of the purge flow of the system 10.

Further, the control unit 36 may determine the operating speed of thegas turbine 12 at which the fuel is isolated. For example, if theexhaust temperature is relatively low during a specific shut-downoperation, more inlet air flow and time may be used to achieve thedesired purging volume. Accordingly, the control unit 36, upondetermining the desired purging volume, may instruct the system 10 toisolate the fuel from the gas turbine 12 at a certain percent of thenormal operating speed of the gas turbine 12. Alternatively, if theexhaust temperature is relatively high during a specific shut-downoperation, less inlet air flow and time may be used to achieve thedesired purging volume. In such a situation, the control unit 36 mayinstruct the system 10 to isolate the fuel at approximately 30 percentof the normal operating speed of the gas turbine 12. In this manner, thecontrol unit 36 is able to account for various speeds of the gas turbine12 during a shut-down operation to meet the desired purging volume ofthe purging operation.

As the system 10 coasts down toward the minimum purging flow rate, atblock 158, an increased total volume is applied to the system 10 untilthe determined purge credit volume is achieved. That is, the steam valve140 and/or the cooling and sealing air system 142 may remain fully openuntil the determined purge credit volume is achieved by the system 10.In particular, opening the steam valve 140 and/or cooling and sealingair system slows the deceleration of the train resulting in more totalvolume before reaching the minimum purge flow. Accordingly, a speed ofthe compressor blades of the compressor section 20 may maintain a speedabove the minimum purge flow velocity for a sufficient amount of time tomeet the purge credit volume.

Subsequently, upon reaching the purge credit volume, at block 160, thesteam valve 140 and/or the cooling and sealing air system 142 may beclosed or may remain closed. By closing the steam valve 140 and thecooling and sealing air system 142, the drag on the shaft may increase,which may result in the speed of the compressor blades of the compressorsection 20 to quickly decrease. Therefore, the system 10 may quicklyshut-down after the desired purge credit volume is met.

FIG. 9 is a block diagram of the system 10 (e.g., a power generationsystem) including the gas turbine 12 and the heat recovery steamgenerator (HRSG) 14, which is generally used to generate power in acombined cycle power plant. The system 10 includes the gas turbine 12,the heat recovery steam generator (HRSG) 14, the fuel system 16, ablower 162, and a water wash system 164. Generally, the system 10 ofFIG. 9 may operate in a similar manner during a purging process of ashut-down operation to the system 10 described in FIG. 1 withmodifications to operation of the gas turbine 12 and/or the fuel system16 to increase the purging volume flow during coast down of the system10.

In particular, the system 10 may increase a purging flow through thesystem 10 using various sources of air (e.g., the blower 162) to boostinlet pressure of the gas turbine 12. For example, the blower 162 mayprovide increased air flow at an aft portion of the turbine section 24.The increased air flow may provide increased purging air flow to thesystem 10 during coast down of the system 10 in such a manner that thedesired purge flow credit is achieved in a reduced amount of time. Inthis manner, the system 10 may achieve the desired purge flow creditbefore the system 10 decelerates to the minimum purge flow rate.Further, the blower 162 may be any fan or air supply system that canprovide increased air flow to the aft portion of the turbine section 24.Additionally, in some embodiments, the blower 162 may be an exhaustframe blower of the gas turbine 12. In such an embodiment, the blower162 may be incorporated in the system 10 without adding any additionalcomponents.

Further, using the water wash system 164 may also increase a purgingflow through the system 10. Generally, the water wash system 164 may beused to clean compressor blades of the compressor section 20 by sprayingwater into the inlet of the compressor section 20 while the compressorsection 20 runs at a reduced speed. Because the compressor section 20operates at a high temperature, the water sprayed into the compressorsection 20 may vaporize and exit the compressor section 20 as watervapor. Accordingly, while air flow at the inlet of the compressorsection 20 is not changed, increased volume resulting from vaporizedwater is provided to the exhaust plenum 99. The water wash system 164may generally begin applying water to the inlet of the compressorsection 20 when the fuel of the gas turbine 12 is secured (e.g., atapproximately 80-90% of the normal operating speed of the gas turbine12), and the water wash system 164 may stop providing water to the inletof the compressor section 20 when the gas turbine 12 reaches a minimumspeed beyond which the water would stop vaporizing. Accordingly, thecontrol unit 36 may instruct the water wash system 164 to cease waterwash operations when the gas turbine 12 reaches approximately 40, 50, or60 percent of the normal operating speed of the gas turbine 12. Theincreased volume provided by the water vaporization may be used duringthe purging process to account for a portion of the desired purge flowcredit when the system 10 shuts down. Therefore, the system 10 mayachieve the desired purge flow credit before the system 10 deceleratesto the minimum purge flow rate.

Additionally, in some embodiments, the fuel system 16 may also be usedto increase the purging flow through the system 10. Generally, the fuelsystem 16 may provide an operation that extinguishes the combustionflame. For example, the fuel system 16 may isolate the fuel source fromthe gas turbine 12 by closing one or more valves (e.g., gas controlvalves, stop valves, etc.). Further, the fuel system 16 may provide adiluent (i.e., a displacement gas) from a displacement gas supply to thegas turbine 12 to further dilute any remaining fuel in the gas turbine12 after the combustion flame is extinguished. It may be appreciatedthat the diluents from the displacement gas supply may provideadditional purging flow to the system 10 when the valves of the fuelsystem 16 are in a specific configuration. The additional purging flowmay enable the system 10 to achieve the desired purge flow credit beforethe system 10 decelerates to the minimum purge flow rate.

While the addition of purging air flow from the blower 162, increasedvolume from the water wash system 164, and/or increased purging flowfrom a displacement gas supply of the fuel system 16 may enable thesystem 10 to achieve the desired purge flow credit before the system 10decelerates to the minimum purge flow rate, these additional purge flowsmay also limit an amount of time that the starting system is applied tothe system to achieve the desired purge flow credit. For example, byincreasing a purging flow volume over the time the gas turbine 12 takesto decelerate to the minimum purge flow rate, more total volume ispurged over that time. Accordingly, the starting system may be used fora smaller amount of time to finish the purging operation when thedesired purge flow credit is not reach before the gas turbine 12decelerates to the minimum purge flow.

Turning now to FIG. 10, a flowchart of a method 170 for purging thesystem 10 during shut-down using additional purging air flow isillustrated. It may be appreciated that the blocks of the method 170 arenot necessarily sequential steps and that certain blocks may beperformed simultaneously or in a different order. As discussed above,receiving purging credit during shut-down of the system 10 may enable aquicker restart of the system 10 as the system 10 may be in a “purgecomplete” condition upon completion of the shut-down. To accomplishpurging during shut-down of the system 10, at block 172, the controlunit 36 may receive a shut-down notification. The shut-down notificationmay be a result of a decreased power demand in a power grid coupled tothe system 10. Additionally, the shut-down notification may also be aresult of a manual shut-down notification or any other stimulus where ashut-down of the system 10 is desirable.

Subsequently, at block 174, the control unit 36 may instruct the fuel tobe isolated from the gas turbine 12 In isolating the fuel from the gasturbine 12, the combustion flame may be extinguished and the system 10may provide coast down air flow through the system 10. The coast downair flow may refer to air flowing through the system 10 due to residual(i.e., unpowered) rotation of the buckets of the turbine section 24, thecompressor blades of the compressor section 22, and/or the buckets andcompressor blades of the steam turbine 132 after extinguishing thecombustion flame.

Additionally, it may be appreciated that isolating the fuel from the gasturbine 12 may occur at approximately 40 percent (or other percentage)of a normal operating speed of the gas turbine 12 to meet the desiredpurge flow volume. Normal operating speed of the gas turbine 12 may bedefined as an operating speed of the gas turbine 12 at which the gasturbine 12 is operated during standard power generating operation.However, it may also be appreciated that depending on the temperature ofthe exhaust, a magnitude of the volume that achieves the purge, and/orthe deceleration of the purge flow of the system 10, the fuel may beisolated at greater than a nominal isolation speed or less than anominal isolation speed. In certain embodiments, the fuel may beisolated at approximately 30 to 100 percent, 30 to 65 percent, 65 to 100percent, and all subranges therein, of the normal operating speed of thegas turbine 12. For example, the fuel may be isolated at approximately30 percent, 35 percent, 45 percent, 50 percent, 55 percent, 60 percent,65 percent, 70 percent, 75 percent, 80 percent, 85 percent, 90 percent,95 percent, or 100 percent of the normal operating speed of the gasturbine 12 and still achieve the desired purge depending on the exhausttemperature at the shut-down request, the magnitude of the purge volume,and the deceleration of the purge flow of the system 10.

Further, the control unit 36 may determine the operating speed of thegas turbine 12 at which the fuel is isolated. For example, if theexhaust temperature is relatively low during a specific shut-downoperation, more inlet air flow and time may be used to achieve thedesired purging volume. Accordingly, the control unit 36, upondetermining the desired purging volume, may instruct the system 10 toisolate the fuel from the gas turbine 12 at a greater than nominalisolation speed. Alternatively, if the exhaust temperature is relativelyhigh during a specific shut-down operation, less inlet air flow and timemay be used to achieve the desired purging volume. In such a situation,the control unit 36 may instruct the system 10 to isolate the fuel at alesser than nominal isolation speed. In this manner, the control unit 36is able to account for various speeds of the gas turbine 12 during ashut-down operation to meet the desired purging volume of the purgingoperation.

Subsequently, at block 176, the control unit 36 may instruct the systemto provide an additional purging flow to the gas turbine 12. Forexample, the control unit 36 may instruct the blower 162 to provideincreased air flow to the inlet of the compressor section 20.Additionally or alternatively, the control unit 36 may instruct thewater wash system 164 to begin a water wash operation, which, asdescribed above in the discussion of FIG. 9, increases the purging flowwhen the water becomes water vapor in the gas turbine 12. Moreover, thecontrol unit 36 may instruct the displacement gas supply 68 to provideadditional purging flow by way of the diluents stored within thedisplacement gas supply 68. Each of the blower 162, the water washsystem 164, and the displacement gas supply 68 may provide additionalpurging flow to the gas turbine either alone or in combination with eachother. Collectively, the blower 162, the water wash system 164, and thedisplacement gas supply 68 may be defined as additional purging flowsources. The control unit 36 may instruct the additional purging flowsources to remain active until the determined purge flow credit isachieved.

Additionally, in some embodiments, the additional purging flow sourcesmay remain active until the system 10 reaches the minimum purging flowrate. At such a time, the system 10 may activate the starting system tomaintain the system 10 at or above the minimum purging flow rate. Bymaintaining the additional purging flow sources in an active state, anamount of time that the starting system is active is reduced. In thismanner, less energy is expended to accomplish the purging process, andthe purging process may be completed in a shorter amount of time.

After the desired purge flow credit is achieved, at block 178, theadditional purging flow sources may be removed from the system 10.Additionally, at this point, any other purge flow increasing applicationapplied to the system 10 may also be removed to enable the system 10 torapidly shut-down. After shut-down of the system 10, the system 10 maybe in a “purge complete” condition without any additional purging uponstart-up.

It may be appreciated that the methods 80, 110, 150, and 170 may all beused alone or in various combinations with each other to achieve thedesired purge value of the system 10 during shut-down of the system 10.It should be noted that the HRSG system may be utilized with eithersimple cycle or combined cycle systems. In addition, the system 10 mayinclude exhaust treatment systems (e.g., selective catalytic reductionsystems, duct burners, diverter dampers, etc.).

This written description uses examples to disclose the subject matter ofthe disclosure, including the best mode, and also to enable any personskilled in the art to practice the disclosed subject matter, includingmaking and using any devices or systems and performing any incorporatedmethods. The patentable scope of the disclosed subject matter is definedby the claims, and may include other examples that occur to thoseskilled in the art. Such other examples are intended to be within thescope of the claims if they have structural elements that do not differfrom the literal language of the claims, or if they include equivalentstructural elements with insubstantial differences from the literallanguages of the claims.

1. A system, comprising: a controller of a gas turbine and heat recoverysteam generator (HRSG) system, comprising: a memory storing instructionsto perform operations of the gas turbine and HRSG system; and aprocessor configured to execute the instructions, wherein theinstructions, when executed by the processor, cause the controller to:control a steam turbine system coupled to the gas turbine and HRSGsystem to release steam to relieve back pressure of a condenser of thesteam turbine system during deceleration of a gas turbine of the gasturbine and HRSG system; receive a first input signal representative ofa first temperature at an inlet of a compressor section of the gasturbine and a second input signal representative of a rotational speedof the gas turbine; calculate an exhaust flow rate of the gas turbineand HRSG system based on at least the first input signal and the secondinput signal; and control the gas turbine and HRSG system to isolate afuel source from the gas turbine at a portion of normal operating speedof the gas turbine sufficient to achieve a predetermined purging volumeduring coast down of air flow through the gas turbine and HRSG systembased on the exhaust flow rate.
 2. The system of claim 1, wherein thesteam turbine system and the gas turbine and HRSG system are coupled toeach other in a single shaft generator system.
 3. The system of claim 1,comprising: a first temperature sensor that provides the first inputsignal, wherein the first temperature sensor is positioned at the inletof the compressor section of the gas turbine; and a rotational speedsensor that provides the second input signal.
 4. The system of claim 1,wherein the instructions, when executed, cause the controller to receiveat least a third input signal representative of a second temperature atan exhaust of the gas turbine or an exhaust stack of an HRSG of the gasturbine and HRSG system, and the exhaust flow rate is based at least inpart on the third input signal in addition to the first input signal andthe second input signal.
 5. The system of claim 1, wherein instructingthe steam turbine system to release steam to relieve back pressure ofthe condenser of the steam turbine system increases an amount of timefor the gas turbine to decelerate below a minimum purging speed of thegas turbine.
 6. The system of claim 1, wherein releasing steam torelieve back pressure of the condenser of the steam turbine systemcomprises opening a cooling and sealing air system of the steam turbinesystem, opening a steam valve of the steam turbine system, or both. 7.The system of claim 1, wherein the instructions, when executed, causethe controller to control the gas turbine and HRSG system to isolate thefuel source when the gas turbine reaches the portion of normal operatingspeed of the gas turbine sufficient to achieve the purging volume whilethe gas turbine operates at a rotational speed greater than a minimumpurge flow requirement of the gas turbine.
 8. The system of claim 1,wherein relieving the back pressure of the condenser of the steamturbine system reduces drag on the gas turbine.
 9. The system of claim8, wherein the instructions, when executed, cause the controller tocontrol the steam turbine system to stop releasing steam when thepredetermined purging volume is achieved.
 10. A method, comprising:utilizing a controller to: control a steam turbine system coupled to agas turbine and heat recovery steam generator (HRSG) system to releasesteam to relieve back pressure of a condenser of the steam turbinesystem; receive a first measurement of a first temperature of the gasturbine and HRSG system from a first sensor, wherein the measurement ofthe first temperature comprises at least a temperature at an inlet of agas turbine of the gas turbine and HRSG system; receive a secondmeasurement of a rotational speed of the gas turbine from a secondsensor; calculate an exhaust volume flow rate of the gas turbine andHRSG system based on at least the first temperature and the rotationalspeed of the gas turbine; obtain a purging volume of the gas turbine andHRSG system that is based on at least a volume of an HRSG of the gasturbine and HRSG system; and control the gas turbine and HRSG system toisolate a fuel source from the gas turbine at a portion of normaloperating speed of the gas turbine sufficient to achieve the purgingvolume during coast down of air flow through the gas turbine and HRSGsystem based on the exhaust volume flow rate.
 11. The method of claim10, wherein the first sensor comprises a temperature sensor positionedat an inlet of a compressor section of the gas turbine, and the secondsensor comprises a rotational speed sensor of the gas turbine.
 12. Themethod of claim 10, comprising utilizing the controller to receive athird measurement of a second temperature of the gas turbine and HRSGsystem via a third sensor, wherein the third sensor comprises atemperature sensor positioned at an exhaust of the gas turbine or anexhaust stack of the HRSG, and calculating the exhaust volume flow ofthe gas turbine and HRSG system is based on at least the secondtemperature.
 13. The method of claim 10, comprising utilizing thecontroller to determine the portion of normal operating speed at whichthe fuel source is isolated from the gas turbine based at least in parton historical data relating to an amount of time the gas turbine takesto reach a minimum purging speed after isolating the fuel source fromthe gas turbine.
 14. The method of claim 10, wherein utilizing thecontroller to control the steam turbine system to release steam torelieve the back pressure of the condenser of the steam turbine systemcomprises at least one of: controlling a first valve of a cooling andsealing air system of the steam turbine system to open; controlling asteam valve of the steam turbine system to open; or controlling both thefirst valve and the steam valve to open.
 15. A tangible, non-transitory,machine-readable-medium, comprising machine-readable instructions to:receive a first measurement of a first temperature of a power generationsystem via a first sensor, wherein the first temperature comprises atemperature at an inlet of a gas turbine of the power generation system;receive a second measurement of a rotational speed of the gas turbinevia a second sensor; calculate exhaust flow rate of the power generationsystem based on at least the first temperature and the rotational speedof the gas turbine; control a steam turbine system coupled in a singleshaft arrangement to the gas turbine to release steam to relieve backpressure of a condenser of the steam turbine system; and control thepower generation system to isolate a fuel source from the gas turbine ata portion of normal operating speed of the power generation systemsufficient to achieve a purging volume during coast down of air flowthrough the power generation system based at least on the exhaust flowrate.
 16. The machine-readable-medium of claim 15, wherein the purgingvolume is based on at least a volume of a defined portion of the powergeneration system that comprises a heat recovery steam generator. 17.The machine-readable-medium of claim 15, wherein the power generationsystem comprises the gas turbine, the steam turbine system, and a heatrecovery steam generator.
 18. The machine-readable-medium of claim 15,wherein the instructions to control the steam turbine system to releasesteam to relieve the back pressure of the condenser of the steam turbinesystem comprises instructions to: control a first valve of cooling andsealing air system of the steam turbine system to open; control a steamvalve of the steam turbine system to open; or control both the firstvalve and the steam valve to open.
 19. The machine-readable-medium ofclaim 15, wherein the purging volume is achieved while the powergeneration system remains operating at a speed greater than a minimumpurging speed of the power generation system.
 20. Themachine-readable-medium of claim 15, comprising machine-readableinstructions to receive a third measurement of a second temperature ofthe power generation system via a third sensor, wherein the third sensorcomprises a second temperature sensor positioned at an exhaust of thegas turbine or an exhaust stack of a heat recovery steam generator ofthe power generation system, and wherein calculating the exhaust volumeflow of the power generation system is based on at least the secondtemperature.